1. Field of the Invention
This invention relates to the removal of carbonyl sulfide from liquid propane utilizing as the principal agent 2-(2-aminoethoxy) ethanol.
2. Description of the Prior Art
Treatment of gasoline plant, refinery, or other processing plant liquid products for removal or conversion of undesirable components including sulfur compounds is a complex and costly necessity for the petroleum fuel processing industry. Such undesirable compounds include, for example, hydrogen sulfide, mercaptans, sulfides and carbonyl sulfide as well as carbon dioxide.
Methods existing prior to the invention described herein for the removal of carbonyl sulfide from natural petroleum fuels have quite often been performed on fuels in a gaseous state. For example, widely relied upon procedures in the natural gas industry for removing sulfide impurities from gaseous state fuels have utilized monoethanolamine (MEA), diethanolamine (DEA), tetraethyleneglycol (TETRA), or diisopropyl amine (DIPA).
It is also well established in the literature that 2-(2-aminoethoxy) ethanol, also known by the trademarked name DIGLYCOLAMINE.RTM., and hereinafter often referred to as DGA, has been used either by itself or in combination with other materials to remove sulfide components from gaseous streams of petroleum fuels and petroleum derived products. Thus, the manufacturer of DGA has stated in a technical bulletin that "the major use of DIGLYCOLAMINE.RTM. brand of 2-(2-aminoethoxy) ethanol is for the removal of hydrogen sulfide (H.sub.2 S) and/or carbon dioxide (CO.sub.2) from gas streams." Jefferson Chemical Company, Inc., Technical Bulletin, DIGLYCOLAMINE.RTM., Jefferson Chemical Company, Inc., 3336 Richmond Ave., Box 53300, Houston, Tex. 77052.
The use of DGA for removing acid gases from a gaseous mixture stream of wet or dry hydrocarbons is the subject of U.S. Pat. No. 3,712,978 (July 12, 1955) and of Canadian Pat. No. 505,164 (Aug. 15, 1954), assigned to the Fluor Corporation, Ltd., Los Angeles, Cal. This is also described in an article entitled "Acid Gas Removal from Natural Gas Using Diglycolamine" by Howard L. Holder, presented at 45th Annual Convention of The Natural Gas Processors Association.
Additionally, it has been reported that MEA and DGA are substantially equivalent in their effectiveness for removing carbonyl sulfide from gaseous systems. Dingman & Moore, Compare DGA and MEA Sweeting Methods, Hydrocarbon Processing, Vol. 47, No. 7, July, 1968.
Jones and Payne have reported success in using a DGA-water mixture as a solvent in an aromatic extraction treatment of hydrogenated pyrolysis gasoline. They have reported that the DGA-water solvent is more effective for removing benzene-toluene and toluene-xylene mixtures from gasoline than other currently used solvents such as TETRA or DEG-DPG mixtures. Jones and Payne, New Solvent to Extract Aromatics, Hydrocarbon Processing, March, 1973, 91-92.
The Naval Research Laboratory has compared the use of DGA with MEA, N,N' dimethylacetamide (DMAC), and tetramethylene sulfone (TMS) as regenerative carbon dioxide absorbants. It was reported that TMS was superior to the other solvents when employed in CO.sub.2 scrubbers on nuclear submarines. Gustafson and Miller, Investigation of Some New Amines as Regenerative Carbon Dioxide Adsorbants, Naval Research Laboratory, NRL Report 6926, July 23, 1969.
DGA has been used by the El Paso Natural Gas Company for the removal of acid gas impurities from gas streams containing 2% or more of total acid gas. In side-by-side comparisons of a mixture of MEA-DEG solvents with DGA, it was found that DGA was capable of producing approximately a 50% saving in capital investment because the more efficient DGA solvent characteristics resulted in reductions of solution pumping horsepower, reboiler drive steam, cooling tower loads, etc. H. L. Holder, Diglycolamine-A Promising New Acid-Gas Remover, The Oil & Gas Journal, May 2, 1966, 83-86.
The need for complete carbonyl sulfide removal from liquid propane is quite apparent when one considers that hydrolysis of carbonyl sulfide results in the production of carbon dioxide and hydrogen sulfide. The reaction becomes distressingly apparent in petroleum treatment systems which incorporate catalytic dehydrators used to dry purified petroleum products. For example, it was reported in 1962 that propane dehydrators used in a Mobil Oil Company underground storage facility started producing hydrogen sulfide in the effluent stream. Investigations established that the inlet stream of gaseous propane contained trace quantities of carbonyl sulfide. Apparently, activated alumina used in the propane dehydrators catalyzed the hydrolysis of carbonyl sulfide and resulted in hydrogen sulfide contaminated effluent. The problem was solved by Mobil Oil Company not by using a solvent to remove the carbonyl sulfide from the inlet propane stream, but by utilizing a silica-alumina absorbant which had been specially treated to prevent the catalyzed hydrolysis. Fairs and Rumbaugh, Carbonyl Sulfide Hydrolyses in Propane Dehydrator, Hydrocarbon Processes and Petroleum REFINER, 41(11), November, 1962, 211.
Shell Oil Company has suggested a method for the removal of carbonyl sulfide and hydrogen sulfide from liquid propane. This process is known as the ADIP process and is based upon an absorption-regeneration cycle using a circulating aqueous solution of an alkanolamine such as diisopropyl amine. Shell Oil indicates that liquid propane treated by the ADIP process results in a carbonyl sulfide content in liquid propane after the treatment of less than 2 ppm by weight. Shell Oil Company, ADIP, Hydrocarbon Processing, April, 1975, 84.
British Pat. No. 1,513,786 (May 29, 1969) assigned to Shell International Research MAATSCHAPPIJ N.V., teaches the separation of acid gases such as carbonyl sulfide and hydrogen sulfide from gaseous mixtures by means of a selective absorbant of the general formula: EQU HO--(CH.sub.2).sub.p --O.sub.q --(CH.sub.2).sub.r --NH.sub.2
wherein p, q and r are integers, and p=2 to 3, q=1 to 4 and r=2 to 3
Signal Oil Company has reported on the treatment of gas plant liquids with DGA. Williams, W. W., Treatment of Gas Plant Liquids with Diglycolamine Agent, paper prepared for presentation at Oklahoma Regional Meeting of the Natural Gas Processors Association, Oklahoma City, Okla., Apr. 12, 1973. In that paper, it was reported that a liquid product mixture was treated with DGA prior to fractionation with the intent of minimizing or possibly eliminating the downstream sweetening processes. Initially, an MEA liquid-liquid contact system was constructed. This was subsequently converted to DGA in order to evaluate mercaptan removal with the added advantage that any carbonyl sulfide reaction with DGA produced regenerable degradation products. Table IV of this report, reproduced in part as Table 1 for convenience below, indicates that the raw product sought to be purified was a complex mixture of straight chain hydrocarbons with only approximately 48% of the mixture consisting of liquid propane. Results of chemical analysis after treatment with DGA, also found in Table IV of this report and reproduced in part below, show that only approximately 25% of the carbonyl sulfide found in the untreated raw product was removed after treatment with DGA, whereas significantly higher percentages of the hydrogen sulfide and mercaptan impurities were removed.
Regarding the foregoing, it becomes exceedingly apparent that the prior art usage of DGA has been nearly universally limited to the removal of acid gases from gaseous hydrocarbon streams.
TABLE 1 ______________________________________ % UNTREATED DGA REMOVAL RAW TREATED OF COMPONENT PRODUCT PRODUCT IMPURITY* ______________________________________ Carbon dioxide 10 ppm NIL 100% Hydrogen sulfide 11 ppm 5 ppm 54.5% Carbonyl sulfide 12 ppm 9 ppm 25% Sulfur dioxide 5 ppm 7 ppm Carbon disulfide NIL 1 ppm Methyl mercaptan 27 ppm 20 ppm 25.9% Ethyl mercaptan 32 ppm 29 ppm 9.5% Propyl mercaptan 25 ppm 13 ppm 48% +disulfides Total mercaptans 91 ppm 66 ppm 27.5% Total sulfur 122 ppm 86 ppm 29.5% ______________________________________ Raw Product Stream Analysis Reproduced from Table IV of Williams, W. W., Treatment of Gas Plant Liquids with Diglycolamine Agent, paper prepared for presentation at Oklahoma Regional Meeting of the Natural Gas Producer Association, Oklahoma City, Oklahoma, April 12, 1973. *This portion of the table was not presented in the original.
The one exception of this use has been the Signal Oil Company treatment of liquid hydrocarbon mixtures with DGA to remove impurities. However, even in this example the effectiveness of removal of carbonyl sulfide from the liquid mixtures has been minimal. Accordingly, prior to the development of the present invention, there has been no commercially acceptable, economically attractive method for substantially reducing the carbonyl sulfide content of liquid propane streams; therefore, the art has long sought a method which can effectively and economically reduce the carbonyl sulfide content absent the disadvantage of low percentage removal of carbonyl sulfide.
Applicant's application Ser. No. 749,464 filed Dec. 10, 1976 discloses an improved method for carbonyl sulfide removal from liquid propane, utilizing DGA as the principal agent in the carbonyl sulfide removal. This present application discloses and claims that same method, the mechanism for carbonyl sulfide removal now being more fully understood and described.